Seismic data acquisition and source-side derivatives generation and application

ABSTRACT

The technologies described herein include systems and methods for performing a first seismic survey and performing a second seismic survey after a predetermined amount of time has lapsed between the first seismic survey and the second seismic survey. The shot times and the shot positions of the second seismic survey may be substantially the same as the shot times and the shot positions of the first seismic survey. After performing the seismic surveys, seismic data generated by the first seismic survey may be processed to generate a first image, and seismic data generated by the second seismic survey may be processed to generate a second image. After generating the first and second images, a difference between the first image and the second image may be computed to generate a time lapse difference image.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of co-pending U.S. patent applicationSer. No. 13/218,881 filed Aug. 26, 2011; which is a continuation of U.S.patent application Ser. No. 13/011,832 filed Jan. 21, 2011, now U.S.Pat. No. 8,203,906 issued Jun. 19, 2012; which is a divisional of U.S.patent application Ser. No. 12/340,625 filed Dec. 19, 2008, now U.S.Pat. No. 7,876,642 issued Jan. 25, 2011; which is a divisional of U.S.patent application Ser. No. 11/459,441 filed Jul. 24, 2006, now U.S.Pat. No. 7,492,665 issued Feb. 17, 2009; all of which are hereinincorporated by reference in their entireties.

BACKGROUND

The following descriptions and examples are not admitted to be prior artby virtue of their inclusion within this section.

Implementations of various technologies described herein generallyrelate to seismic acquisition. In a seismic survey, a source may beactivated to generate energy, which may be reflected back by the earth'ssub-surface layers. The resultant seismic wavefield may be sampled by anarray of seismic receivers disposed at a distance from the seismicsource. Each receiver may be configured to acquire seismic data, whichare normally in the form of a record or trace representing the value ofsome characteristic of the seismic wavefield against time. Informationabout the earth's sub-surface can be obtained from the acquired seismicdata.

Typically, a plurality of sources and receivers are arranged in a grid,such that the recorded data from the wavefields may substantially coverthe entire area of exploration and with sufficient resolution to detectthe variation of the sub-surface structure over small spatial distances.The wavefields recorded by the receivers may be a result of thesuperposition of many waves having different paths through the earth'ssub-surface before finally reaching the receivers. This makes thereconstruction of the earth sub-surface difficult. One objective ofseismic data processing is to separate the wavefields into coherentwaves in connection with creating an accurate image of the earth'ssub-surface layers. Because seismic data acquisition is very expensive,it is desirable to increase the distance between the grid points andstill provide sufficient resolution or use the same or tighter grid andachieve finer resolution.

In a time-lapse seismic survey, a survey may be performed in the samelocation as a previous survey for the purpose of comparing thesub-surface structure interpretations of the two surveys. For optimalresults, it may be desirable for the sources to be activated at the samelocations and the receivers to be located at the same locations in bothsurveys. This precision may be very difficult. Therefore, a method orsystem designed to minimize the detrimental effects of inaccuracies inpositioning the sources and receivers may be very desirable.

SUMMARY

Described herein are implementations of various technologies foracquiring monopole source data and multi-pole source data, as well asapplications of monopole and multi-pole data. Monopole data may bedefined as the wavefield data resulting from the activation of a singlesource or source group, which may be defined as a plurality of sourcesacting together as a single source. Multi-pole data, including dipoledata, may be defined as the wavefield data resulting from two or moredifferent sources or source groups that are activated in closeproximity. In one implementation, the dipole or multi-pole data may beacquired by activating source groups in close proximity according toorthogonal sequences. The dipole or multi-pole data from the receiversmay be decoded using the same orthogonal sequences, such that thewavefields resulting from the different sources can be separated. Theorthogonal sequences may be constructed in many different ways dependingon the needs and application of the resulting multi-pole data.

Described herein are also implementations of various technologies for amethod for acquiring seismic data. In one implementation, the method mayinclude emitting a first source signal based on a first activationsequence, emitting a second source signal based on a second activationsequence that is orthogonal to the first activation sequence, recordingseismic data in response to the first source signal and in response tothe second source signal and decoding the seismic data based on thefirst activation sequence and the second activation sequence.

Described herein are also implementations of various technologies for aseismic data acquisition system, which may include a first source grouphaving a plurality of seismic sources arranged therein according to afirst activation sequence, a second source group having a plurality ofseismic sources arranged therein according to a second activationsequence and a source controller coupled to the first source group andthe second source group. The source controller may be configured toactivate each seismic source in the first source group according to thefirst activation sequence and each seismic source in the second sourcegroup according to the second activation sequence. The first activationsequence is orthogonal to the second activation sequence.

Described herein are also implementations of various technologies forusing the monopole and multi-pole data. In one implementation, thedipole data may be used to calculate various derivatives of thewavefield. In another implementation, the multi-pole data may be used tocalculate higher order derivatives and other relevant data. The monopoledata, multi-pole data, derivatives and other data may be used to deghostseismic images, interpolate data for use in time-lapse seismic surveys,multiple suppression, and imaging (e.g., through stereo-tomography).

Described herein are also implementations of various technologies for amethod for generating and applying source-side derivatives. In oneimplementation, the method may include acquiring a response to a firstseismic source and a response to a second seismic source at a pluralityof source locations, deriving a source-side derivative from the responseto the first seismic source and the response to the second seismicsource for each source location and applying the source-sidederivatives.

Described herein are also implementations of various technologies for amethod for processing seismic data. In one implementation, the methodmay include processing seismic data acquired using a first source signalemitted based on a first activation sequence and a second source signalemitted based on a second activation sequence orthogonal to the firstactivation sequence and decoding the seismic data based on the firstactivation sequence and the second activation sequence.

Described herein are also implementations of various technologiesdirected to the reduction of residual shot noise in seismic data. In oneimplementation, shot times may be used in processing the reduction ofresidual shot noise. In another implementation, shot times as well asshot positions may be constrained during acquisition such that spatialcoherence in the residual shot noise may be enhanced. In yet anotherimplementation, the constrained shot times and positions may be usedduring repeat surveys such that residual shot noise may be reduced intime-lapse difference images. In another implementation, a typicalsurvey may be performed using alternating orthogonal sequences. Then,the monopole data may be decoded using the same orthogonal sequences,such that residual shot noise can be distinguished.

The claimed subject matter is not limited to implementations thatachieve any or all of the noted advantages. Further, the summary sectionis provided to introduce a selection of concepts in a simplified formthat are further described below in the detailed description section.The summary section is not intended to identify key features oressential features of the claimed subject matter, nor is it intended tobe used to limit the scope of the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

It is to be noted that the appended drawings illustrate only typicalembodiments of this invention and are therefore not to be consideredlimiting of its scope, for the invention may admit to other equallyeffective embodiments.

FIGS. 1A-B illustrate a typical marine seismic acquisition survey systemfor performing 3D or 4D surveys.

FIGS. 2A-B illustrate mutually orthogonal encoding sequences and theirapplication for seismic source encoding in accordance withimplementations of various technologies described herein.

FIGS. 3A-G illustrate various seismic source arrays in accordance withimplementations of various technologies described herein.

FIG. 4A-B illustrate an alternative implementation combining the use ofan in-line source array as illustrated in FIG. 3F and the concept ofleaving out non-activated sources as illustrated in FIG. 3G.

FIG. 5 illustrates a flow diagram of a method for encoding and decodingseismic data in accordance with implementations of various technologiesdescribed herein.

FIG. 6 illustrates a block diagram for a system performing a seismicsurvey and processing the seismic data in accordance withimplementations of various technologies described herein.

FIG. 7 illustrates an example of interpolation using data from threeshot positions obtained in accordance with implementations of varioustechnologies described herein.

FIGS. 8A-B illustrate the noise tolerance of interpolation over thetypical seismic spectrum using dipole and monopole data.

FIG. 9 illustrates a simple diagram of residual shot noise.

FIG. 10 illustrates a flow a diagram of a method for reducing residualshot noise during seismic data processing in accordance withimplementations of various techniques described herein.

FIGS. 11A-F illustrate the methodology illustrated in FIG. 10 using anattenuating wave to depict the seismic data recorded in response to eachshot.

FIG. 12 illustrates a method for generating a time-lapse differenceimage in accordance with implementations of various techniques describedherein.

FIG. 13 illustrates a method for acquiring and processing seismic datausing orthogonal sequences to reduce residual shot noise.

FIG. 14 illustrates a computer network, into which implementations ofvarious technologies described herein may be implemented.

DETAILED DESCRIPTION

For simplicity, where marine seismic survey is discussed, positive Xdirection is the direction where the towing vessel is going. Withreference to FIG. 1A, the Y direction is the horizontal directionperpendicular to the X direction. The Y direction may also be referredto as cross-line direction. With reference to FIG. 1B, the positive Zdirection is a vertical-up direction. For clarity, when referring to anairgun or similar single source, the word source will be used. Whenreferring to a plurality of sources used collectively as a singlesource, the words source group will be used. When referring to a line ofsources towed by a vessel, the words source array will be used.

FIGS. 1A-B illustrate a typical marine seismic acquisition survey system10 for performing 3D or 4D surveys. Although implementations of varioustechnologies described herein are with reference to the marine seismicacquisition survey system 10, it should be understood that otherimplementations may use any seismic acquisition system.

The typical marine seismic acquisition system 10 may include a vessel 11carrying control components 14 and towing a plurality of seismic sources16 and a plurality of streamers 18 equipped with seismic receivers 21.The vessel 11 may further include a GPS receiver 12 coupled to thecontrol components 14, which may be an integrated computer-based seismicnavigation (TRINAVT™), source controller (TRISOR™), and recording(TRIACQ™) system (collectively, TRILOGY™). The seismic sources 16 may bemade of the same types of sources, or they may be made of differenttypes of sources. The sources may be any type of common seismicgenerator, such as air guns, water guns, steam injection sources,explosive sources such as dynamite or gas injection followed bydetonation and the like. The streamers 18 may be towed by means of theirrespective lead-ins 20, which may be made from high strength steel orfiber-reinforced cables that convey electrical power, control and datasignals between the vessel 11 and the streamers 18. Each streamer 18 mayinclude a plurality of seismic receivers 21, distributed at spacedintervals along the streamer's length. Each receiver 21 may be ahydrophone sensor and the like. Each receiver 21 may be separately wiredso that its output signal can be separately digitized and filtered,thereby permitting sophisticated processing known as digital groupforming, as described in commonly assigned U.S. Pat. No. 6,684,160,which is incorporated herein by reference. Further, the streamers 18 mayinclude a plurality of inline streamer steering devices (SSDs) 38, alsoknown as “birds,” such as Q-FIN™ birds of the kind described in commonlyassigned U.S. Pat. No. 6,671,223, which is incorporated herein byreference. The SSDs may be distributed at appropriate intervals alongthe streamers 18 for controlling the streamers' depth and lateralmovement.

During acquisition, the seismic sources 16 and the seismic streamers 18may be deployed from the vessel 11 and towed very slowly, for exampleabout 5 knots. The seismic sources 16 may be periodically activated, forexample every 10 seconds or so, emitting seismic energy in the form ofan acoustic wave through the water. Each source 16 may be activatedindependently or simultaneously with other sources. The acoustic wavemay result in one or more wavefields that travel coherently into theearth E underlying the water W (see FIG. 1B). As the wavefields strikeinterfaces 4 between earth formations, or strata, they may be reflectedback through the earth E and water W along paths 5 to the variousreceivers 21 where the wavefields (e.g., pressure waves in the case ofair gun sources) may be converted to electrical signals, digitized andtransmitted to the integrated computer-based seismic navigation, sourcecontroller, and recording system 14 (see FIG. 1A) in the vessel 11 viathe streamers 18 and lead-ins 20. Through analysis of these detectedsignals, it may be possible to determine the shape, position andlithology of the sub-sea formations, including those formations that maylikely contain hydrocarbon deposits.

The representation of the sub-surface layers in the survey area may beformed by combining seismic data collected along a plurality of saillines. Although ideally the sail lines are approximately straight, wind,water currents, waves, steering of the survey vessel and the like maycause the sail lines to be less than perfectly linear. Furthermore, theseismic data may be collected along paths that are purposefullynon-linear. For example, it may be desirable to repeat the non-linearsail lines of a prior seismic survey for purposes of time-lapsecomparison, also known as a 4D survey. Non-linear sail lines may exhibitshapes including elliptical paths, circular paths, and figure-8 paths,among others.

A single survey vessel may tow a single receiver array along each of thesail lines. Alternatively, a plurality of survey vessels may tow aplurality of receiver arrays along a corresponding plurality of the saillines. In various alternatives, the data may be collected during asingle survey conducted over a short period of time such as one day, orit may be collected in multiple surveys performed at different times.Inclement weather and/or high seas may force a survey to be suspendedbefore resuming hours or days later. In some implementations, historicaldata from previous surveys performed months or years earlier may becombined with new data to extend the survey or to fill in deficienciesin coverage that may be introduced by currents, obstacles such asplatforms and the like. Data from repeat surveys may also be used toanalyze and monitor changes in productive oil and/or gas reservoirs.

The accuracy and/or resolution of the image formed using the acquisitiondata may be limited by uncertainties as to the actual path of theseismic sources and receivers through the water. Although the surveyvessel typically attempts to tow the seismic sources so that itsgeometric center-of-source follows a desired sail line, water currents,wind, waves and the like may divert one or more sources from the desiredpath. The accuracy and/or resolution may further be limited by noisesuperimposed on the wavefield of interest. Noise may be caused byresidual shot noise, waves and the like. The accuracy and/or resolutionmay further be limited by constraints on the quantity of data collected.If a source or source group is activated in close time proximity to theprevious shot, the responses received by receivers may becomesuperimposed with each other. Thus, a sufficient time interval must beallowed between shots. Because the vessel continues to move during thetime interval, the quantity of data collected over a certain area may beconstrained.

In a typical marine seismic survey as described above, monopole data maybe recorded. Monopole data refer to the data recorded at the receiversin response to a single source or source group. Dipole data refer to thedata recorded at the receivers in response to two sources or sourcegroups activated in close proximity. Dipole data may be obtained bysubtracting the monopole response from each of the source locations anddividing by the distance between the source locations. Close proximity,as used in this application, may refer to the distance between twosources or source groups that is within a fraction of the minimumwavelength of the seismic waves of interest. In most seismic surveys,close proximity may be about 3 meters to about 15 meters. Multi-poledata refer to data recorded at the receivers in response to multiplesources or source groups activated in close proximity with appropriatepolarities. Currently, dipole or multi-pole data may be acquired byconducting two or more surveys, each survey collecting monopole data inclose proximity to the shot positions. Dipole or multi-pole data mayalso be acquired by sequentially activating sources in a single surveysuch that two or more monopole responses may be recorded in closeproximity to each pre-defined shot position. With dipole or multi-poledata, source-side derivatives may be generated and used in variousapplications to enhance image accuracy and resolution. However, thesecurrent methods of acquiring multi-pole data significantly increase thesurvey costs. Accordingly, implementations of various technologiesdescribed herein are directed to simultaneously acquiring dipole andmulti-pole data with limited cost increase.

Encoding/Decoding Sources

FIGS. 2A-B illustrate mutually orthogonal encoding sequences and theirapplication for seismic source encoding in accordance withimplementations of various technologies described herein. Digitalencoding and decoding have been used in many communication applications,such as telecommunications. The theories and applications are discussedin telecommunication literatures, such as “Sequence Design forCommunications Application,” by Pingzhi Fan and Michael Darnell, 1996.However, such encoding and decoding have never been used in seismic dataacquisition or processing. In seismic acquisition, source groups may beencoded using digital sequences where each source ‘pop’ represents aspike in a sequence. The sequence for one source group may be selectedsuch that it is orthogonal to the sequences for other source groups.Each sequence may be orthogonal to all the other sequences, which meansthat the cross-correlation between any pair of sequences issubstantially zero for all time-shifts, while the auto-correlation(e.g., the correlation of a sequence with itself) has a large value onlyfor the zero time-shift and is substantially zero for all non-zerotime-shifts. In one implementation, the large value may be a spikehaving amplitude of substantially one or unity. In a cross-correlationor auto-correlation, the similarity between two discrete data series ismeasured for different relative time-shifts between the series bymultiplying the amplitude of the shifted and un-shifted data series on apoint-by-point basis and summing (integrating) over all the points. Byutilizing orthogonal sequences, the response from each source group maybe decoded, and thus isolated from the superposition of responses fromall the other source groups by cross-correlation with each encodingsequence. In one implementation, the sources within the source groupsmay be fired simultaneously. In another implementation, the sourceswithin the source groups may be fired sequentially.

FIG. 2A illustrates a simplified example of a pair of digital sequencesin accordance with implementations of various technologies describedherein. Sequence 220 may be represented digitally as (0, 1, 0, 1, 0, 0,1, 1) and sequence 230 as (1, 0, 1, 0, 1, 1, 0, 0). These sequences 220and 230 may also be represented as activated or non-activated sources.As such, “1” may indicate an activation of the source at a point intime, which may be represented as a spike. On the other hand, “0” mayindicate that the source is silent, or not activated, at a point intime.

In one implementation, each activation or non-activation may beseparated by a fixed time period T such that the entire firing sequenceperiod may be on the order of approximately 200 ms. For example, at timeequal to zero, sequence 220 has a digital “0” indicating no activation.However at time equal to zero, sequence 230 contains a digital “1”indicating an activation, as shown by the spike. While each activationor non-activation has been described as representing a single source, itshould be understood that in some implementations each activation ornon-activation may represent a plurality of sources.

FIG. 2B illustrates how two source groups 200 and 210 may be activatedsimultaneously according to sequences 220 and 230 illustrated in FIG.2A. Source group 200 may follow sequence 220 and source group 210 mayfollow sequence 230. Source groups 200 and 210 may be towed across theshot position 240 with source group 200 crossing location (r0) andsource group 210 crossing (r1) in close proximity to (r0). At time equalto 0, the first source in each source group crosses the shot position240. According to the sequences in FIG. 2A, source 221 of source group200 may not be activated and source 231 of source group 210 may beactivated, as indicated by the ‘x’. At time equal to 1T, the two sourcegroups 200 and 210 may be towed forward such that the second pair ofsources in source groups 200 and 210 crosses the shot position 240.Source 222 of source group 200 may be activated while source 232 ofsource group 210 may not. As time goes on, the two source groups 200 and210 may continuously move forward such that each source may be activatedor not activated according to their respective activation sequence.Although FIG. 2B illustrates the activation of a pair of source groupsin close proximity with respect to the Y direction, many otherarrangements may be implemented, some of which are illustrated in FIGS.3B-F below. FIG. 2B illustrates the use of two source groups; however,many source groups may be used simultaneously with the same number ofmutually orthogonal codes used to encode each of the source groups.Depending on the number of source groups to be encoded/decoded, anysuitable orthogonal sequence set with a sufficient number of orthogonalcodes may be constructed and implemented.

In one implementation, orthogonal sequences may have the property thatthe cross-correlation with any other sequence from the same orthogonalsequence set substantially equals to zero for all time-shifts. Also, theorthogonal sequences may have the property that the auto-correlation ofa sequence results in a discrete delta-function, which only has a large,non-zero value at zero time-shift (i.e., when the sequence is notshifted with respect to itself) and substantially equals to zero for allother time-shifts. However, the requirements for the cross-correlationand auto-correlation may be relaxed, as long as the main lobe of theauto-correlation is narrow and has an amplitude that is substantiallygreater than the side-lobes of the auto-correlation as well as thenoise-level in the cross-correlation resulting from imperfectorthogonality. Also, in one implementation, the encoded source sequencesshould have as short duration as possible while at the same time thetime-delay between consecutive activations (pops) should be big enoughto prevent cross-talk between sources due to reduced resolution in thefrequency domain. Such sequences may be described in more detail in Fan,P., Darnell, M., 1996, Sequence Design for Communications Applications,Chapter 15, Optical Orthogonal Sequences, Research Studies Press, whichis incorporated herein by reference. Unlike the application intelecommunication where the sequences may be mostly periodic, theresponses from earth may be typically aperiodic. Optical orthogonalsequences typically have better periodic correlations than aperiodicones and may need to be adapted for use in seismic surveys. Theorthogonal sequences may also be determined by simulated annealing,which is an optimization algorithm that searches for the minimum valueof a function. Such technique may be described in more detail inGrønaas, H., 2000, Simultaneous Acquisition with Impulsive MarineSeismic Sources, OTC Summer Student Internal Report, which isincorporated herein by reference.

Referring to FIG. 2A, mathematically, encoding and decoding may beperformed as follows. The source group 200 signal convolved with thesequence 220 is:

$\begin{matrix}{{S\left( {{r\; 0},t} \right)} = {{S(t)}*{{seq}(220)}}} \\{= {S(t)*\left\lbrack {{{delta}\left( {t - T} \right)} + {{delta}\left( {t - {3T}} \right)} + {{delta}\left( {t - {6T}} \right)} + {{delta}\left( {t - {7\; T}} \right)}} \right\rbrack}} \\{{= {{S\left( {t - T} \right)} + {S\left( {t - {3T}} \right)} + {S\left( {t - {6T}} \right)} + {S\left( {t - {7T}} \right)}}},}\end{matrix}$

where * denotes convolution, delta(t−T) denotes a delta-function delayedby time T, seq(220) denotes the orthogonal sequence and S(t) denotes thesource-time function of the individual sources in the source group. Thelast identity follows from the fact that convolution with adelta-function implies replacing the argument of the original functionwith the argument of the delta-function. Thus, encoding may results in asuperposition of delayed versions of the original source-time function.This, of course, is exactly how encoding is done in practice.

Similarly, the source group 210 signal convolved with the sequence 230is:

$\begin{matrix}{{S\left( {{r\; 1},t} \right)} = {S(t)*{{seq}(230)}}} \\{= {S(t)*\left\lbrack {{{delta}\left( {t - {0T}} \right)} + {{delta}\left( {t - {2T}} \right)} + {{delta}\left( {t - {4T}} \right)} + {{delta}\left( {t - {5T}} \right)}} \right\rbrack}} \\{= {{S\left( {t - {0T}} \right)} + {S\left( {t - {2T}} \right)} + {S\left( {t - {4T}} \right)} + {S\left( {t - {5T}} \right)}}}\end{matrix}$

At receivers, the receiver signal is the superposition of the effectivesource signals, convolved with the Earth's response:

$\begin{matrix}{{R\left( {r,t} \right)} = {{{{GF}\left( {r,{r\; 0},t} \right)}*{S\left( {{r\; 0},t} \right)}} + {{{GF}\left( {r,{r\; 1},t} \right)}*{S\left( {{r\; 1},t} \right)}}}} \\{{= {{S(t)}*\left\lbrack {{{{GF}\left( {r,{r\; 0},t} \right)}*{{seq}(220)}} + {{{GF}\left( {r,{r\; 1},t} \right)}*{{seq}(230)}}} \right\rbrack}},}\end{matrix}$

where GF(r,r0,t) denotes the so-called Green's function (i.e., theresponse of the subsurface recorded as a function of time in point r,due to an impulsive source in point (r0) and GF(r,r1,t) has a similarinterpretation.

The received signal may be decoded by cross-correlation with thesequences. For example, cross-correlating the received response withsequence 220 gives:

$\begin{matrix}{{R\; 200\left( {r,t} \right)} = {{{seq}(220)} \times {S(t)}*\begin{bmatrix}{{{{GF}\left( {r,{r\; 0},t} \right)}*{{seq}(220)}} +} \\{{GF}\left( {r,{r\; 1},t} \right)*{{seq}(230)}}\end{bmatrix}}} \\{= {{S(t)}*\begin{bmatrix}{{{{GF}\left( {r,{r\; 0},t} \right)}*{{seq}(220)} \times {{seq}(220)}} +} \\{{GF}\left( {r,{r\; 1},t} \right)*{{seq}(220)} \times {{seq}(230)}}\end{bmatrix}}} \\{= {{S(t)}*\left\lbrack {{{{GF}\left( {r,{r\; 0},t} \right)}*{{delta}(t)}} + {{{GF}\left( {r,{r\; 1},t} \right)}*{{zeros}(t)}}} \right\rbrack}} \\{{= {{S(t)}*{{GF}\left( {r,{r\; 0},t} \right)}}},}\end{matrix}$

where x denotes cross-correlation and zeros(t) is a trace with valuesclose to zero, denoting the approximate orthogonality of the sequences220 and 230, i.e., seq(220)×seq(230)=zeros(t). Note that theauto-correlation of seq(220) approximates a delta-function, i.e.,seq(220)×seq(220)=delta(t).

The decoded function R200(r,t) is S(t)*GF(r,r0,t), which is the responseto source group 200 only. The effect from source group 210 has beenremoved. Similarly, R210(x,y,z,t) may be deduced, which is the responseto source group 210 only. Therefore, if the proper orthogonal sequencesmay be constructed, the seismic responses to each source group that isencoded may be decoded, even if the source groups are activatedvirtually simultaneously.

Source Arrangement

FIGS. 3A-G illustrate various seismic source arrays in accordance withimplementations of various technologies described herein. FIG. 3Aillustrates a prior art source array 16 with a plurality of seismicsources, such as air-guns or water-guns, towed behind a vessel 11 in alinear fashion along the sail line. The sources may be controlled by asource controller and may typically be activated at the same time. Thistype of source array may be used to sequentially fire sources withorthogonal sequencing. In one implementation, the sources may be firedin accordance with a first sequence, e.g., sequence 220, and then firedwith a second sequence, e.g., sequence 230, such that the sequencesalternate.

Using the technologies described herein, dipole or multi-pole data maybe obtained by activating two or more separate sources (or sourcegroups) in close proximity, about 3-15 meters. Using orthogonalsequences as described in FIGS. 2A-B, two or more source groups may befired simultaneously to obtain this data. FIGS. 3B-G illustrate a fewpossible source array implementations that may be used to obtain dipoleor multi-pole data using the various technologies described herein.

FIG. 3B illustrates a source array 316 towed behind a vessel 11 in whichtwo source groups may be towed in parallel offset in close proximity inthe Y direction. At each source location, a pair of two sources, e.g.,301 and 311, 302 and 312, may be installed. Each source may beindividually controlled by a source controller and activated at theappropriate time independently. Each source may be a single air-gun orthe like, or a plurality of sources acting as a single source in theform of a single point source, a linear source or otherwise. The twosource groups may be fired simultaneously according to the orthogonalsequences selected, with only one source in each pair of sources beingactivated as it passes over the shot position as illustrated in FIG. 2B.In one implementation, the distance between the two sources within apair (e.g., distance between sources 301 and 311) may be in such closeproximity that in some situation the pair may be considered a singlesource.

FIG. 3C illustrates a source array 326 where source pairs (e.g., 301 and321, 302 and 322) may be arranged in close proximity in the Z directionsuch that dipole data in the Z direction may be obtained. FIG. 3Dillustrates a source array with three source groups where three sources(a cluster of sources) may be located in close proximity at each sourcelocation such as 301, 311 and 321. The arrangement in FIG. 3D mayprovide multi-pole data in both the Y direction and Z directionsimultaneously. If the sources within a cluster have differentX-direction offset, then they may also provide dipole data in the Xdirection.

In the implementations illustrated in FIGS. 3B-D, the source groups maybe arranged such that the sources are separated by a predefined distancewithin the pair or cluster, but other implementations may be possible.For example, in FIG. 3E, two linear source arrays 346 and 356 may betowed closely together by a vessel 11. The sources within the arrays 346and 356 form multiple pairs, such as 341 and 351, 342 and 352. Thedistance between each source in a pair may be in close proximity,similar to those pairs as shown in FIGS. 3B-D. However, since the arrays346 and 356 may be independently towed and steered, the relativepositions of the sources 341 and 351, 342 and 352 may not be keptconstant during a survey. The change in relative distance between thesources in a pair may be accommodated when the activation position ofeach source is recorded. This implementation may be useful for adaptingexisting source arrays for use with implementations of varioustechnologies described herein. The arrays 246 and 256 may be towed toform pairs in the Y direction similar to the one shown in FIG. 3B, or inthe Z direction as shown in FIG. 3C. If more than two arrays are towedclosely, then an array similar to the one shown in FIG. 3D may beformed.

FIG. 3F shows another alternative source array 366, where source groupsmay be towed by the same cable, but are separated slightly from the sailline. This may be termed an in-line source array. When the source arrayis towed, sources 361 and 371 (or 362 and 372) may form a pair when theypass the shot position in close proximity. The distance between thesources in a pair may be similar to that of the source pairs shown inFIGS. 3B-E, but the pair of sources as shown in FIGS. 3B-E would passthe same location at the same time, while pairs in FIG. 3F would passthe same location at different times.

In the implementations shown in FIG. 3B-F, each source group contains asource in every pair location regardless of which sources may beactivated. The sequence at a shot position may be implemented byactivating an appropriate source at each time interval while othersources are not activated.

FIG. 3G illustrates a source array 376 in which the sequence may bebuilt into the array by leaving out sources that are not activated. Inthis example, the activation sequences 220 and 230 of FIG. 2A may beimplemented in a manner explained below. The individual sources may bedistributed in a linear array such that distance between sources may beproportional to the activation time interval of each shot in thesequence. For example, at time equal to zero, source 231 crosses theshot position (r0) and may be fired. At time equal to 1T, source 222crosses the shot position (r1) in close proximity to shot position (r0)and may be fired. Thus, a vessel moving at a constant speed allows thesesources to be activated at the correct times over the shot position withthe sources from different source groups in close proximity. The array376 in FIG. 3G may be designed in the Y direction similar to the array316 shown in FIG. 3B, or in the Z direction as shown by array 326 inFIG. 3C. The array 376 in FIG. 3G may be designed with an additionalsource group such that an array similar to the one shown in FIG. 3D maybe formed.

FIG. 4A-B illustrate an alternative implementation combining the use ofan in-line source array as illustrated in FIG. 3F and the concept ofleaving out non-activated sources as illustrated in FIG. 3G. FIG. 4Aillustrates the activation of digital sequence 420, which is (1, 0, 1,0), and digital sequence 430, which is (0, 1, 0, 1). FIG. 4B illustratesthe activation of sources in the single array where sources are arrangedoff-center of the sail line. In this implementation, every sourcepassing the shot position 440 at (r0) or (r1) may be activated becauseof the arrangement of the sources and the sequences. Sources activatedat (r0) make up one source group while sources activated at (r1) formthe second source group.

The seismic sources used in the arrays illustrated in FIGS. 3A-G and 4Bmay be the same types of sources or they may different types of sources.The sources may be any type of common seismic generator, such as airguns, water guns, steam injection sources, explosive sources such asdynamite and gas injection followed by detonation and the like. Somesources have complementary properties in that some may be positivesources, generating positive seismic impulses, and some may be negativesources, generating negative seismic impulses. When the sources in anarray are of the same type, the sequence may only be either activated(1) or not-activated (0). So the sequence may be composed of 1's and0's. When the coding is limited to 1's and 0's, sequences may be moredifficult to construct and longer in order to satisfy the orthogonalityrequirements. However, when the sources are of complimentary type, thesequence may be positively activated (1), negatively activated (−1) ornot activated (0). As such, the sequence may be composed of 1's −1's and0's. Thus, the sequences may be easier to construct and shorter becausea greater number of orthogonal sequences may be available for encoding.For example, in seismic acquisition, air-gun and water-gun sources haveopposite pressure amplitudes, and as such, using a combination of thesesources may simplify encoding and decoding.

Method for Encoding and Decoding Seismic Data

FIG. 5 illustrates a flow diagram of a method for encoding and decodingseismic data in accordance with implementations of various technologiesdescribed herein. At step 512, the shot positions and receiver positionsmay be determined. For example, a grid of shot positions may be planned.At step 514, the orthogonal sequences may be determined. Selectingappropriate orthogonal sequences may be based upon several factorsincluding the number of source groups used and the types of sourcesused. For example, if source side derivatives in both the Y and Zdirections are desired, three source groups may be used requiring threeseparate mutually orthogonal sequences. Also, if air and water guns areused, orthogonal sequences with −1, 0 and 1 may be used. If differenttypes of sources are to be used, then the allocations of differentsources may also be determined. At step 516, sources may be installed atthe determined locations in the source arrays. Sources and receivers maythen be moved to the desired locations and the sources may then beactivated according to the encoding sequences. At step 518, receiversmay record data from all sources.

After the seismic data is collected and checked for quality control, thedecoding process may be conducted, either on board the vessel in thefield or back in a central office. At step 522, the recorded data may beseparated by shot position and then correlated with each orthogonalsequence. Each correlation procedure generates one set of data that maybe the response to the activation of one source group. After thecorrelation with all of the orthogonal sequences, the seismic data foreach shot position may be separated into individual seismic data due toeach source group in the source array. For example, in FIG. 2B the shotrecord for shot position 240 contains the seismic response to bothsource groups 200 and 210 that were fired simultaneously. Usingcorrelation of orthogonal sequences 220 and 230, the shot record forshot position 240 may be divided into separate records for positions(r0) and (r1) corresponding to the separate source groups 200 and 210firing unique orthogonal sequences 220 and 230. The decoded data,grouped together for each shot position, forms multi-pole data sets. Thedata may be used in a multitude of applications. For example, at step524, further data processing for desired applications may be performedsuch as calculating source side derivatives, monopole responses and thelike. At step 526, applications such as vertical deghosting, horizontalinterpolation and stereo-tomography may be performed.

Controller Diagram

FIG. 6 illustrates a block diagram for a system performing a seismicsurvey and processing the seismic data in accordance withimplementations of various technologies described herein. An overallcontroller 610 may include a source controller 612, receiver controller614, a code sequence generator 616 and other controllers 620. When aseismic survey plan is prepared, the positions of sources and receiversmay be determined and forwarded to source controller 612 and receivercontroller 614. The appropriate code sequences may be generated by thecode generator 616 and sent to the source controller 612. The sourcecontroller 612 may then activate the sources 622 at the appropriatetimes. The receivers 624 may record the responses due to all of thesesources. The received data may be recorded in a storage device 630 forfurther processing. The above referenced controllers may be positionedin the field or integrated into other components of the seismic surveysystem.

Source-Side Derivatives

Once dipole or multi-pole data has been acquired using the technologiesdescribed herein, derivatives may be calculated. The source-sidederivative across two or more source positions may be calculated bytaking the difference of the two Green's Functions (GF) and dividing bythe distance between the two sources, as expressed by the followingequation,

${\partial P_{x_{i}}} = {\frac{{\overset{->}{GF}}_{1} - {\overset{->}{GF}}_{2}}{\Delta \; x_{i}} + {O\left( {\Delta \; x_{i}^{2}} \right)}}$

If the gradient is required in several directions, then duringacquisition separate source pairs in required directions may beimplemented, as described in FIGS. 2B-G. Higher order derivatives in oneor several directions may also be calculated if three or more sourcearrays were used in acquisition. For example, dipole data may be used togenerate first degree derivative data. Tri-pole data may be used togenerate second degree derivatives. Higher order derivatives, which mayimprove various applications of source-side derivatives, may also begenerated.

Monopole Response

Dipole data yielding source side derivatives may be highly advantageous;however, a quality monopole response must also be obtained in additionto the dipole data in order for the source side derivatives to be used.Many applications utilize the lowest order term, the monopole data, andthen utilize higher order terms such as derivatives. Since the seismicdata decoded into the individual records may be noisier than typicalmonopole data, a combined monopole response for each pair or cluster ofsources may be derived. One method averages the dipole or multi-poledata to calculate the monopole response. Another method of derivingmonopole data uses Wiener Deconvolution on the combined response beforedecoding. In this method, the entire pair or cluster may be considered asingle source. The monopole source signature may be the sum of thesource groups activated simultaneously and the effective size of themonopole source pair/cluster may be the spatial distribution of allindividual sources. The monopole data derived using this method may beas good as data acquired using conventional means to collect monopoledata.

Deghosting

Deghosting a wavefield generally refers to the process of removing thedown-going wavefield from the up-going wavefield. A prior art techniquefor deghosting data on the source-side sorts the data intocommon-receiver gathers, invokes reciprocity and uses translationallyinvariant Green's functions. However, this prior art technique mayrequire dense shot spacing, may be prone to perturbation on the sourceside, may assume a lateral invariant sub-surface, may assume a flat seasurface and may require 3D or in-line 2D acquisition geometry. Most ofthese constraints may be avoided when deghosting is performed using thevertical source-side derivative obtained using the implementations ofvarious technologies described herein.

The equations for deghosting may either be written in terms of up- anddown-going pressure P or vertical particle velocity V. As an example,the expression for deghosting of P will be described below. The equationfor up/down decomposition or deghosting of the wavefield in thefrequency-wavenumber domain may be written as:

$\begin{matrix}{P^{D} = {\frac{1}{2}\left( {P + {\frac{\rho\omega}{k_{z}}V_{z}}} \right)}} & (1)\end{matrix}$

where P^(D) is the deghosted down-going part of the pressure on thesource-side (capital letters denote wavenumber-frequency domainexpressions), P is the total pressure, V_(Z) is the correspondingvertical component of particle velocity, k_(Z) is the absolute value ofthe vertical wavenumber (may be expressed in terms of frequency andhorizontal wavenumbers using the dispersion relation in water), ω is theangular frequency and ρ is the density of water.

The time derivative of V_(Z) is proportional to the vertical pressuregradient ∂_(Z)P through the equation of motion such that V_(Z) may becalculated from pressure gradient data:

$\begin{matrix}{V_{z} = {{- \frac{1}{\; {\omega\rho}}}{\partial_{z}P}}} & (2)\end{matrix}$

Substituting Equation (2) into Equation (1), Equation (1) may thereforebecome

$\begin{matrix}{P^{D} = {\frac{1}{2}{\left( {P + {\frac{}{k_{z}}{\partial_{z}P}}} \right).}}} & (3)\end{matrix}$

Equation (3) may be approximated using compact filters such that lowwavenumbers may be deghosted well. Although a larger class of spatiallycompact filters may be of interest, a very simple one is discussed here,which may be accurate for vertical incidence only (zero horizontalwavenumbers). The vertical incidence approximation applied to equation(3) yields

$\begin{matrix}{P^{D} \approx {\frac{1}{2}\left( {P - {\frac{c}{\; \omega}{\partial_{z}P}}} \right)}} & (4)\end{matrix}$

where c is the velocity of water. The second term in the bracket ofequation (3) may now be interpreted in the space-time domain as a scaledversion of the vertical derivative of pressure integrated in time.

The source-side deghosting approximation given by equation (4) may beeffectively implemented when dipole or multi-pole data in the Zdirection is obtained using the implementations of various technologiesdescribed herein; and when the monopole data is derived from theobtained dipole data using implementations of various technologiesdescribed herein. The average of the shots may be represented by P andtheir difference divided by the separation in depth between the shotsmay be represented by the source-side derivative, ∂_(Z)P, which isaccurate for small separation distances (e.g., 5 m or less). Here thedistance between shot positions must be reduced because waves propagateclose to vertical; and therefore, the sampling may need to be finer whenthe derivative is calculated in the vertical direction.

For the application of source-side deghosting, the reduction in thesignal-to-noise ratio (S/N) due to approximate orthogonality may be muchless destructive as the sources occupy the same position in the lateralplane and therefore excite the same wavenumbers when scattering from thesub-surface. The error introduced by the insufficient separation of thetwo digital sequences during decoding may be similar to that introducedby inaccuracies in source calibration in nature. Even with theinaccuracy in the decoding of the dipole or multi-pole data, thesource-side deghosting may be typically more effective than other priorart methods as mentioned above.

Horizontal Interpolation

There are several applications where interpolation between sourcepositions in the horizontal plane may be of great benefit, such astime-lapse repeat survey matching to baseline survey positions, surfacerelated multiple eliminations (SRMEs) and the like. For example, in atime-lapse seismic survey, shot positions may not be consistent acrosssurveys. But, interpolation may be used to calculate shot position datafrom known shot positions. Typically, interpolation may be performedusing monopole data only. However, interpolation results may be enhancedwhen the multi-pole data collected using the technologies describedherein may be used for interpolation in addition to the monopole data.The noise in the data may restrict the interpolation distance.

FIG. 7 illustrates an example of interpolation using data from threeshot positions obtained in accordance with implementations of varioustechnologies described herein. In FIG. 7, the source position, Z, may beinterpolated between three known shot positions, A, B and C. Each sourceposition A, B and C may consist of a pair of source groups encoded usingorthogonal sequences such that lateral derivatives in both the X- andY-directions may be calculated. Source position Z may then beinterpolated from the data, as discussed below.

By using a ‘Dutch’ Taylor expansion the following formula may be derivedto interpolate from each source position,

$\begin{matrix}{{P_{I}\left( {{x + {\Delta \; x}},{y + {\Delta \; y}}} \right)} = {{P\left( {x,y} \right)} + {\frac{1}{2}{\left\{ {{\Delta \; x{\partial_{x}{P\left( {x,y} \right)}}} + {\Delta \; y{\partial_{y}{P\left( {x,y} \right)}}}} \right\}.}}}} & (5)\end{matrix}$

Using baricentric weighting, the three interpolations from each sourceposition may be combined to give the estimate by interpolation of thepoint Z

P _(Z) =aP _(IA) +bP _(IB) +cP _(IC)  (6)

where a, b and c are the areas shown in FIG. 7.

If more accurate interpolation is desired, then more source points maybe encoded and decoded to generate more source-side data. With theseinterpolations the exact locations of sources becomes less importantwhich eases the demand for accuracy on vessel navigation and streamerlocations. This may also lengthen the seismic surveying season which isoften limited by the weather and other navigation conditions.

FIGS. 8A-B illustrate the noise tolerance of interpolation over thetypical seismic spectrum using dipole and monopole data. Theinterpolation performance was tested using simulation data. Theamplitude of a plane wave was calculated at points along a line x forvarying frequency between 0-50 Hz and angles of incidence of 0-40degrees. This allowed points along the line to be interpolated using thecalculated amplitudes from the ends of the line. These interpolatedpoints were then compared to the actual calculated value at the centerpoint of the line. The difference between the absolute value of theinterpolated result and the absolute value of the calculated result wasdetermined for each time and frequency and integrated over the period ofthe wave. The result was normalized by the initial calculated resultsuch that a percentage error between the calculated result andinterpolated result for each frequency was determined simply bymultiplication by 100.

In order to determine how well this interpolation performs with noiselevels that may be expected in the decoded data that may be used tocalculate the spatial derivatives, values were drawn from Gaussiandistributions with mean zero and standard deviation equal to the noiselevel expected. In the case of the monopole response, this noise levelmay be 0.0075; and in the case of the points used to determine thedipole response, the noise level may be 0.25. These are normalized noiselevels. Interpolations were carried out 200 times so that a standarddeviation for the final result may be determined for 200 realizations ofthe Gaussian noise.

In FIGS. 8A-B, the solid line represents the noise free case for thepercentage difference between the expected value and the interpolatedvalue. The dashed lines demonstrate expected noise and are the resultplus and minus the standard deviation determined for the 200realizations of the Gaussian noise.

In FIG. 8A, the results using monopole and dipole data are shown. Atsmall incidental angles (<5 degree) or low frequencies (<20 Hz), theinterpolation errors are very small. Even with noise at 25%, the errorsare still relatively small, less than 10% and tolerable. When thefrequency or incidence angle increases, the error in the interpolationmay increase. In FIG. 8B, the results using both monopole data only areshown. As shown, the interpolation error using monopole data may be muchworse than that using both monopole and dipole data, especially athigher frequencies and larger incident angles. For example, at about 10%error tolerance, the useable range using monopole data is less thanabout 30 Hz at less than a 5 degree incident angle or less than about 7Hz at a 20 degree incident angle. For the same 10% error tolerance, theuseable range using monopole and dipole data is up to 40 Hz at a 10degree incident angle or up to 18 Hz at a 20 degree incident angle.Monopole data combined with dipole data provides superior interpolationresults even at much higher noise levels. The test results show that byusing data decoded from an encoded data set, it is possible to improveon simple monopole interpolation between two source positions, eventhough the noise introduced into the result may be higher in the case ofthe dipole.

Imaging

Various imaging application may be enhanced or become possible using themonopole and multi-pole data obtained in accordance with implementationsof various technologies described herein. For example, stereo-tomographymay be performed using derivatives from both the source side and thereceiver side.

Residual Shot Noise Attenuation

In a typical marine seismic survey, the source may be fired as it passesover pre-defined shot positions, termed ‘shooting on position.’ Theseshot positions may typically be separated by equal distances in a grid.The distance between shot positions may typically be dictated by theapproximate time required between shots. However when the survey isperformed, since the shot positions are defined, the actual timeinterval between shots may vary as the vessel speed varies due to wind,currents, waves and the like. The time period containing useful data fora shot, which may be called the duration of interest, may beapproximately 6 seconds or less. However, more time may be required forthe seismic wave from the previous shot, termed residual shot noise, toattenuate to an acceptable level. Because of residual shot noise, shotsmay typically be fired approximately every 10 seconds to providesufficient time for the residual shot noise to substantially dissipate.Since the slowest vessel speed is approximately 2.5 meters per second,the distance between shots is typically 25 meters. If the time andtherefore, distance between shots could be reduced, greater imageresolution as well as many other benefits could be achieved.

FIG. 9 illustrates a simple diagram of residual shot noise. As brieflymentioned above, residual shot noise generally constrains the time anddistance between the shots. In a seismic survey, a source may be firedat time equal to t1 as represented by the spike at shot 1. The receiversmay begin recording a seismic wave 10 in response to shot 1 at time, t2,after the shot is fired. This seismic wave 10 may attenuate, or getsmaller over time. At some time, t3, the next acquisition source may befired as represented by the spike at shot 2. The receivers may beginrecording a seismic wave 20 in response to shot 2 at time t4. However,at time t4, the receivers may still be recording a portion of seismicwave 10 that still resonates from the previous shot. This attenuatingseismic wave 10 from the previous shot may be considered noise whenevaluating the seismic wave field response 20 from the second shot, theshot of interest, and may be referred to as the residual shot noise. Theportion of the seismic wave that contains desirable information may betermed the signal. Noise is the undesirable information that typicallyaccompanies the signal.

FIG. 10 illustrates a flow diagram of a method 1000 for reducingresidual shot noise during seismic data processing in accordance withimplementations of various techniques described herein. Variousimplementations may require that the firing time for each shot berecorded with accuracy on the order of milliseconds. FIGS. 11A-Fillustrate the methodology illustrated in FIG. 10 using an attenuatingwave to depict the seismic data recorded in response to each shot. FIG.11A illustrates a simplified example of seismic data in response toshots 98, 99 and 100. At step 1010, the seismic data may be separatedinto shot records by synchronizing the seismic data with reference tothe firing time of each shot at time equal to zero. For instance, theshot record for shot 100 contains the seismic data in response to shot100 and begins at the time shot 100 was fired and continues for theduration of interest, typically 6 seconds or less. FIG. 11B illustratesa simplified example of the synchronized seismic data for shot 100 withtime equal to zero at the firing time of shot 100, represented by thespike. Although the duration of interest is described herein astypically being 6 seconds or less, it should be understood that in someimplementations the duration of interest may be less than 6 seconds,such as from about 2 seconds to about 6 seconds, or greater than 6seconds, such as from about 6 seconds to about 10 seconds. In oneimplementation, a lateral coherence filter may be applied to the seismicdata for each shot to enhance the seismic image for the shot. Thelateral coherence filter may be applied in the common offset domain.

At step 1020, the seismic data may again be synchronized, but now withreference to the firing time of the previous shot at time equal to zero.Here, the seismic record will be expanded over a longer period of time,i.e., the time from the previous shot through the duration of interestof the shot of interest. FIG. 11C illustrates a simplified example ofthe seismic data for shot 100 synchronized with reference to theprevious shot's 99 firing time. At step 1030, a lateral coherence filtermay be applied to the seismic data for each shot to enhance the seismicimage for the shot. Again, a lateral coherence filter in the commonoffset domain may be applied. In this manner, the response due to theprevious shot may be enhanced and the response due to the shot ofinterest may be minimized. FIG. 11D illustrates the result of applyingthe lateral coherence filter to the seismic data for shot 100 havingbeen referenced to the firing time of shot 99. The signal from shot 100may be removed by the filter as incoherent noise while the signal fromshot 99 may be retained as a coherent signal. It may be noted that thisprocess reverses the goal of isolating shot 100, the shot of interest,in order to more effectively remove the noise, shot 99, in step 1050below.

Since the response due to the previous shot 99 may be consideredresidual shot noise with respect to the seismic data of shot 100, whichis the shot of interest, the residual shot noise affecting the shot ofinterest may be isolated. Accordingly, at step 1040, the seismic datafrom step 1030, the isolated residual shot noise, may be resynchronizedagain with reference to the shot of interest's firing time. In effect,the portion of the residual shot noise that occurs after the shot ofinterest has been fired will be selected, as illustrated in FIG. 11E. Atstep 1050, the residual shot noise data from step 1040 (FIG. 11E) may besubtracted from the original synchronized data from step 1010 (FIG. 11B)leaving a noise-reduced record for the shot of interest as illustratedin FIG. 11F. At step 1060, the noise-reduced data may be processed toproduce the seismic image.

In one implementation, a typical marine seismic survey may be performedto acquire the seismic data. The firing times may be recorded accuratelyfor use in processing. The seismic data may then be processed using themethod described in FIG. 10.

In another implementation, the removal of residual shot noise may befurther enhanced by using pre-defined shot times, in addition topre-defined shot positions. While the shot times may be at regular timeintervals such as every 6s, the shot times may be selected such thatcoherency may be enhanced. In general, coherency filters may performbetter with time intervals between shots that are different, butdefined. For example, the time interval between shots may be graduallyincreased by a few milliseconds per shot such that the residual shotnoise would appear as data with a defined and non-zero move-out. In oneimplementation, the time intervals may be as follows: 6s, 6s+4 ms, 6s+8ms and so on. The residual shot noise may therefore have a differentslope than the signal of interest. Any method for varying the timing ofshots may be employed, including increasing or decreasing the timeinterval between shots and the like. Although seismic surveys aretypically performed with pre-defined shot positions, some surveys areconducted with pre-defined shot times.

However, no method is currently employed that pre-defines both shotposition and shot time. To accomplish a marine seismic survey in whichthe time and location of shots may both be controlled, it may benecessary to tightly control the speed of the vessel towing thestreamers of receivers. The sources may be fired at precisely thecorrect times and the vessel speed may be adjusted such that the shotpositions match the pre-defined shot positions within a tolerance ofapproximately 2.5 meters of the planned position. The control systemthat constrains the shot position may control the vessel speed. Thedistance between shots may be proportional to the average speed of thevessel during the shot time interval. If, for example, the shot pointswere found to be falling progressively further ahead of the nominalpositions, the vessel speed may be reduced. The seismic data collectedmay then be processed using the method described in FIG. 10.

The method of FIG. 10 may be used to separate residual shot noise fromthe signal. If the residual shot noise may be removed or reduced, thetime between shots may be reduced from the typical 10 second interval.The time between shots may be shortened to the duration of interest,typically approximately 6 seconds. If the separation of residual shotnoise is highly effective, the time between shots may be even shortersuch that the durations of interest may overlap. Shortening the timebetween shots may result in smaller distances between shots, increasedimage resolution, reduced time for survey completion and the like.

FIG. 12 illustrates a method for generating a time-lapse differenceimage in accordance with implementations of various techniques describedherein. In a time-lapse seismic survey, a repeat survey may be performedin the same location as a previous baseline survey for the purpose ofcomparing the images produced by the two surveys. The images may besubtracted to create the time-lapse difference image. A time-lapsedifference image represents any change to the subsurface layers sincethe last survey was performed. For example, the difference in image mayreveal the places in which the oil-and-water contact has movedindicating the areas from which oil has been pumped. If theoil-and-water contact is not changing in all expected areas of thereservoir, another well may be installed to tap into that area. Usingcurrent methods, residual shot noise may contribute to the backgroundnoise of the time-lapse difference image because the residual shot noisemay not be coherent between the two surveys. At step 1210, a baselineseismic survey may be performed in which the shot times are accuratelyrecorded. The baseline survey may be conducted with any varying timeintervals between shots, whether constant, increasing, decreasing andthe like, as described in the above paragraphs. At step 1220, after someperiod of time, a repeat survey may be performed using the same shottimes to an accuracy of less than 4 ms, and approximately the same shotpositions. The repeat shot positions may be within approximately 2.5meters of the baseline shot positions. At step 1230, the seismic datafrom the two surveys may be processed. The seismic data may be processedby any method as long as both sets of seismic data are processed in thesame manner. At step 1240, the resulting images from each survey may besubtracted and the difference in the surveys represents the change overtime. Since the residual shot noise from both surveys should be verysimilar, the majority will subtract or cancel out. Therefore theresidual shot noise in the resultant time-lapse difference image may besignificantly reduced.

FIG. 13 illustrates a method for acquiring and processing seismic datausing orthogonal sequences to reduce residual shot noise. At step 1310,at least two mutually orthogonal sequences may be selected. At step1320, a seismic survey may be performed using the orthogonal sequenceson alternate shots. For example, shot 99 may be fired in accordance withorthogonal sequence A; then shot 100 may be fired with orthogonalsequence B. Shot 101 may then be fired with sequence A and so on. Atstep 1330, the response to each shot may be separated from the residualshot noise resulting from the previous shot by decoding the responses inaccordance with implementations of various technologies describedherein. For example, the shot record for shot 100 may be correlated withthe orthogonal sequences A and B to isolate the signal from shot 100 andthe noise from shot 99. At step 1340, the noise reduced signal data maybe processed to produce a seismic image. While two orthogonal sequenceswere used in this illustration, more orthogonal sequences may beutilized.

In another implementation, the methods described in FIGS. 10 and 13 maybe combined. For example, orthogonal sequences may be used in additionto constraining the shot times and shot positions. In this manner, thedata acquired may be separated using the orthogonal sequences. Then, themethod described in FIG. 10 may be used to further reduce the residualshot noise in the seismic data.

FIG. 14 illustrates a computer network 1400, into which implementationsof various technologies described herein may be implemented. Thecomputer network 1400 may include a system computer 1430, which may beimplemented as any conventional personal computer or server. However,those skilled in the art will appreciate that implementations of varioustechnologies described herein may be practiced in other computer systemconfigurations, including hypertext transfer protocol (HTTP) servers,hand-held devices, multiprocessor systems, microprocessor-based orprogrammable consumer electronics, network PCs, minicomputers, mainframecomputers, and the like.

The system computer 1430 may be in communication with disk storagedevices 1429, 1431, and 1433, which may be external hard disk storagedevices. It is contemplated that disk storage devices 1429, 1431, and1433 are conventional hard disk drives, and as such, will be implementedby way of a local area network or by remote access. Of course, whiledisk storage devices 1429, 1431 and 1433 are illustrated as separatedevices, a single disk storage device may be used to store any and allof the program instructions, measurement data and results as desired.

In one implementation, seismic data from the receivers may be stored indisk storage device 1431. The system computer 1430 may retrieve theappropriate data from the disk storage device 1431 to process seismicdata according to program instructions that correspond toimplementations of various technologies described herein. The programinstructions may be written in a computer programming language, such asC++, Java and the like. The program instructions may be stored in acomputer-readable medium, such as program disk storage device 1433. Suchcomputer-readable media may include computer storage media andcommunication media. Computer storage media may include volatile andnon-volatile, and removable and non-removable media implemented in anymethod or technology for storage of information, such ascomputer-readable instructions, data structures, program modules orother data. Computer storage media may further include RAM, ROM,erasable programmable read-only memory (EPROM), electrically erasableprogrammable read-only memory (EEPROM), flash memory or other solidstate memory technology, CD-ROM, digital versatile disks (DVD), or otheroptical storage, magnetic cassettes, magnetic tape, magnetic diskstorage or other magnetic storage devices, or any other medium which canbe used to store the desired information and which can be accessed bythe computing system 100. Communication media may embody computerreadable instructions, data structures, program modules or other data ina modulated data signal, such as a carrier wave or other transportmechanism and may include any information delivery media. The term“modulated data signal” may mean a signal that has one or more of itscharacteristics set or changed in such a manner as to encode informationin the signal. By way of example, and not limitation, communicationmedia may include wired media such as a wired network or direct-wiredconnection, and wireless media such as acoustic, RF, infrared and otherwireless media. Combinations of the any of the above may also beincluded within the scope of computer readable media.

In one implementation, the system computer 1430 may present outputprimarily onto graphics display 1427, or alternatively via printer 1428.The system computer 1430 may store the results of the methods describedabove on disk storage 1429, for later use and further analysis. Thekeyboard 1426 and the pointing device (e.g., a mouse, trackball or thelike) 1425 may be provided with the system computer 1430 to enableinteractive operation.

The system computer 1430 may be located at a data center remote from thesurvey region. The system computer 1430 may be in communication with thereceivers (either directly or via a recording unit, not shown), toreceive signals indicative of the reflected seismic energy. Thesesignals, after conventional formatting and other initial processing, maybe stored by the system computer 1430 as digital data in the diskstorage 1431 for subsequent retrieval and processing in the mannerdescribed above. While FIG. 14 illustrates the disk storage 1431 asdirectly connected to the system computer 1430, it is also contemplatedthat the disk storage device 1431 may be accessible through a local areanetwork or by remote access. Furthermore, while disk storage devices1429, 1431 are illustrated as separate devices for storing input seismicdata and analysis results, the disk storage devices 1429, 1431 may beimplemented within a single disk drive (either together with orseparately from program disk storage device 1433), or in any otherconventional manner as will be fully understood by one of skill in theart having reference to this specification.

Although the various technologies described herein where discussed inreference to marine seismic surveys, the various technologies describedherein may also be applicable to land seismic survey, sea-bed seismicsurvey or others, where dipole or multi-pole data may be acquired.

While the foregoing is directed to implementations of varioustechnologies described herein, other and further implementations may bedevised without departing from the basic scope thereof, which may bedetermined by the claims that follow. Although the subject matter hasbeen described in language specific to structural features and/ormethodological acts, it is to be understood that the subject matterdefined in the appended claims is not necessarily limited to thespecific features or acts described above. Rather, the specific featuresand acts described above are disclosed as example forms of implementingthe claims.

What is claimed is:
 1. A method for acquiring and processing seismicdata, comprising: deploying at least two marine seismic sources in abody of water at substantially the same longitudinal position from avessel; activating the at least two marine seismic sources in aplurality of firing sequences during a seismic survey, at least onefiring sequence having a different time delay between the firing of theseismic source and the start of the seismic recording; and recording theseismic data in response to activating the at least two marine seismicsources.
 2. The method of claim 1, wherein the time delay for the atleast one firing sequence is variable.
 3. The method of claim 1, whereinthe time delay for the at least one firing sequence is constant.
 4. Themethod of claim 1, wherein the time delay for the at least one firingsequence increases over time.
 5. The method of claim 1, wherein the timedelay for the at least one firing sequence decreases over time.
 6. Themethod of claim 1, further comprising synchronizing the recorded seismicdata with reference to the firing time of each shot.
 7. The method ofclaim 1, further comprising applying a lateral coherence filter to therecorded seismic data for each shot.
 8. The method of claim 1, whereinthe at least two marine seismic sources are deployed at differentdepths.
 9. The method of claim 1, wherein the at least two marineseismic sources are deployed at substantially the same depth and arelaterally offset from one another.